LONDON (Reuters) - U.S. refineries are processing the lightest cocktail of crudes for almost a quarter of a century, as they run out of room to switch light imported oils with domestic shale production.
In March, U.S. refineries processed crude with an average gravity of 31.95 degrees API, the lightest combination since April 1991, according to data from the U.S. Energy Information Administration (EIA).
Higher numbers on the API scale correspond to lighter crude oils. API gravity is a scale employed for measuring the density of fluids such as crude and refined fuels. API gravity of 31.95 degrees corresponds to roughly 864 kilograms per cubic meter.
The average density of crude processed at U.S. refineries has fallen by 3 kilograms per cubic meter over the last 12 months and 10 kilograms since 2008, which may not sound much, but density has varied in a narrow band of just 16 kilograms over the last 30 years (link.reuters.com/pyh84w).
The trend towards lighter feedstock presents a challenge for oil refineries seeking to make the best use of their equipment.
Refiners take pains to keep density stable by carefully selecting which crudes to purchase and blending them to achieve the correct average properties.
Most units in a refinery are constrained by volume and designed to operate with maximum efficiency only if the average quality of the feedstock can be kept within a fairly narrow range.
For example, the trays in an atmospheric distillation tower are arranged to produce cuts in roughly fixed proportions.
A crude cocktail lighter than intended will produce more gases and very light fractions at the top of the tower, which the refinery may not be able to handle efficiently, and less heavy residual, leaving vacuum distillation and coking units underemployed.
For this reason, refiners try to keep average feedstock quality stable within a fairly tight range to squeeze the maximum efficiency from their plants.
The shale revolution has challenged refinery efficiency because it has forced U.S. refineries to process a large volume of very light oils.
North Dakota’s Bakken crude can be a light as 810-820 kilograms per cubic meter, which is 50-60 kilograms per cubic meter lighter than the long run U.S. refinery average. Oils from Eagle Ford are even lighter.
U.S. refiners have tried to keep average density steady by reducing the amount of light oil they buy and purchase from North and West Africa (Nigeria, Algeria and Angola) as well as the North Sea.
But imports of light crudes have now been reduced close to zero which means that refiners are reaching the limits of this strategy.
One alternative is to blend very light domestic crude with very heavy oils, for example from Canada, to achieve the same average mix.
Even as imports of light oils from West Africa have been almost eliminated, the United States is importing record quantities of mostly heavier oil from Canada.
Clever blending has not been enough to stop the average feedstock from becoming lighter and lighter over the last year.
There are questions about how much longer this trend can continue before it starts to have a significant impact on refinery efficiency.
Crude produced in the United States cannot generally be exported, except to Canada, under laws enacted following the oil crisis of 1973/74.
So the rising production of light crudes from shale plays in North Dakota and Texas must therefore be processed in the United States.
Light crudes from shale are a good match for the simpler refineries along the East Coast, which previously processed similar crudes from the North Sea and West Africa.
But they are not ideal for the more complex refineries elsewhere in the country, especially those along the Gulf Coast, which have invested heavily in cokers and other units for processing heavier crudes.
Refiners will still purchase the oil, but usually demand a significant discount, which leaves domestic crude producers frustrated about prices, and refiners with crudes which are not optimal for their refineries.
For domestic shale producers, the increasing mismatch between the crudes being produced in the United States and those preferred by refiners is a strong reason to lift the crude export ban.
Most oil refiners have taken no public position on the future of the export ban. While all U.S. refiners benefit from cheaper domestic feedstock, they are also increasingly dependent on exporting refined fuels to customers in Latin America, Europe and Asia, so are reluctant to endorse trade restrictions.
But Consumers and Refiners United for Domestic Energy (CRUDE), which lobbies on behalf of a small group of mostly East Coast refiners opposed to lifting the ban, has noted the mismatch has not stopped refiners from processing record volumes of crude so far in 2015.
Domestic shale production, much of it transported in tank cars along the railroads, has become increasingly important for East Coast refiners, since it matches the needs of their refineries most closely.
In February, rail receipts of crude accounted for more than half of all crude processed on the East Coast, according to the Energy Information Administration.
For the CRUDE, whose members include Monroe Energy (Trainer refinery), PBF Energy (Delaware City, Paulsboro and Toledo refineries), and Philadelphia Energy Solutions (Philadelphia refinery) access to cheap feedstock is vital.
In the short term, the plunge in oil prices and the downturn in shale drilling are likely to cause domestic crude production to stabilize, removing some of the pressure on the refining sector and shale prices.
In the longer term, however, there are important questions about how to handle the growing volume of very light shale production.
One option is to lift the ban on crude exports, allowing the market to find the most efficient way to process available feedstocks (exporting some light oils while continuing to import some heavier ones).
If the export ban remains, refineries would have to make capital investments to handle a large volume of lighter feedstocks.
There are some options to replace more light oil imports, increase capacity utilization, and debottleneck existing units (for example by adjusting the trays and condenser units in distillation towers).
But most of these cheap options have already been taken, according to an assessment produced by the EIA (“Technical options for processing additional light tight oil volumes within the United States” Apr 6, 2015).
To handle an increased volume of domestic light crude, refiners would need to invest in new distillation and secondary processing units, most of which are expensive, according to the agency.
In reality, the refining system may be running out of easy options for handling light oil.
If the export ban is not lifted within the next couple of years, substantial discounts between domestic and international crudes could re-emerge and even widen in future.
Editing by William Hardy